Oil sands is essentially comprised of a matrix of bitumen, solid mineral material and water.
The bitumen component of oil sands includes hydrocarbons which are typically quite viscous at normal in situ temperatures and which act as a binder for the other components of the oil sands. For example, bitumen has been defined by the United Nations Institute for Training and Research as a hydrocarbon with a viscosity greater than 104 mPa s (at deposit temperature) and a density greater than 1000 kg/m3 at 15.6 degrees Celsius.
The solid mineral material component of oil sands typically consists of sand, rock, silt and clay. Solid mineral material may be present in oil sands as coarse mineral material or fine mineral material. The accepted division between coarse mineral material and fine mineral material is typically a particle size of about 44 microns. Solid mineral material having a particle size greater than about 44 microns is typically considered to be coarse mineral material, while solid mineral material having a particle size less than about 44 microns is typically considered to be fine mineral material. Sand and rock are generally present in oil sands as coarse mineral material, while silt and clay are generally present in oil sands as fine mineral material.
A typical deposit of oil sands may contain (by weight) about 10 percent bitumen, up to about 6 percent water, with the remainder being comprised of solid mineral material, which may include a relatively small amount of impurities such as humic matter and heavy minerals.
Water based technologies are typically used to extract bitumen from oil sands ore originating from the Athabasca area in northeastern Alberta, Canada. A variety of water based technologies exist, including the Clark “hot water” process and a variety of other processes which may use hot water, warm water or cold water in association with a variety of different separation apparatus.
In a typical water based oil sands extraction process, the oil sands ore is first mixed with water to form an aqueous slurry. The slurry is then processed to release bitumen from within the oil sands matrix and prepare the bitumen for separation from the slurry, thereby providing a conditioned slurry. The conditioned slurry is then processed in one or more separation apparatus which promote the formation of a primary bitumen froth while rejecting coarse mineral material and much of the fine mineral material and water. The separation apparatus may also produce a middlings stream from which a secondary bitumen froth may be scavenged. This secondary bitumen froth may be added to the primary bitumen froth or may be kept separate from the primary bitumen froth.
A typical bitumen froth (comprising a primary bitumen froth and/or a secondary bitumen froth) may contain (by weight) about 60 percent bitumen, about 30 percent water and about 10 percent solid mineral material, wherein a large proportion of the solid mineral material is fine mineral material. The bitumen which is present in a typical bitumen froth is typically comprised of both non-asphaltenic material and asphaltenes.
This bitumen froth is typically subjected to a froth treatment process in order to reduce its solid mineral material and water concentration by separating the bitumen froth into a bitumen product and froth treatment tailings.
In a typical froth treatment process, the bitumen froth is diluted with a froth treatment diluent to provide a density gradient between the hydrocarbon phase and the water phase and to lower the viscosity of the hydrocarbon phase. The diluted bitumen froth is then subjected to separation by solvent extraction in one or more solvent extraction apparatus in order to produce the bitumen product and the froth treatment tailings. Exemplary solvent extraction apparatus include gravity settling vessels, inclined plate separators and centrifuges.
Some commercial froth treatment processes use naphthenic type diluents (defined as froth treatment diluents which consist essentially of or contain a significant amount of one or more aromatic compounds). Examples of naphthenic type diluents include toluene (a light aromatic compound) and naphtha, which may be comprised of both aromatic and non-aromatic compounds.
Other commercial froth treatment processes use paraffinic type diluents (defined as froth treatment diluents which consist essentially of or contain significant amounts of one or more relatively short-chained aliphatic compounds). Examples of paraffinic type diluents are C4 to C8 aliphatic compounds and natural gas condensate, which typically contains short-chained aliphatic compounds and may also contain small amounts of aromatic compounds.
Froth treatment processes which use naphthenic type diluents (i.e., naphthenic froth treatment processes) typically result in a relatively high bitumen recovery (perhaps about 98 percent), but also typically result in a bitumen product which has a relatively high solid mineral material and water concentration.
Froth treatment processes which use paraffinic type diluents (i.e., paraffinic froth treatment processes) typically result in a relatively lower bitumen recovery (in comparison with naphthenic froth treatment processes), and in a bitumen product which has a relatively lower solid mineral material and water concentration (in comparison with naphthenic froth treatment processes). Both the relatively lower bitumen recovery and the relatively lower solid mineral material and water concentration may be attributable to the phenomenon of asphaltene precipitation, which occurs in paraffinic froth treatment processes when the concentration of the paraffinic type diluent exceeds a critical level. This asphaltene precipitation results in bitumen being lost to the froth treatment tailings, but also provides a cleaning effect in which the precipitating asphaltenes trap solid mineral material and water as they precipitate, thereby separating the solid mineral material and the water from the bitumen froth.
Froth treatment tailings therefore typically contain solid mineral material, water, froth treatment diluent, and small amounts of residual bitumen (perhaps about 2-12 percent of the bitumen which was contained in the original bitumen froth, depending upon whether the froth treatment process uses a naphthenic type diluent or a paraffinic type diluent).
Much of the residual froth treatment diluent remaining in froth treatment tailings is typically recovered from the froth treatment tailings in a tailings solvent recovery unit (TSRU). The froth treatment tailings (including the tailings bitumen) are then typically disposed of in a tailings pond.
A significant amount of bitumen from the original oil sands ore is therefore typically lost to the froth treatment tailings as residual bitumen. There are both environmental incentives and economic incentives for recovering all or a portion of this residual bitumen.
In addition, the solid mineral material which is included in the froth treatment tailings comprises an amount of heavy minerals. Heavy minerals are typically considered to be solid mineral material which has a specific gravity greater than that of quartz (i.e., a specific gravity greater than about 2.65). The heavy minerals in the solid mineral material which is contained in typical froth treatment tailings may include titanium bearing minerals such as rutile (TiO2), anatase (TiO2), ilmenite (FeTiO3) and leucoxene (typically an alteration product of ilmenite) and zirconium bearing minerals such as zircon (ZrSiO4). Titanium and zirconium bearing minerals are typically used as feedstocks for manufacturing engineered materials due to their inherent properties.
Although oil sands ore may contain a relatively low concentration of heavy minerals, it is known that these heavy minerals tend to concentrate in the bitumen froth which is extracted from the oil sands ore, and therefore become concentrated in the froth treatment tailings which result from froth treatment processes, primarily as coarse mineral material. As a result, froth treatment tailings may typically contain a sufficient concentration of heavy minerals to provide an economic incentive to recover these heavy minerals from the froth treatment tailings.
Froth treatment tailings may be further processed to recover bitumen and/or heavy minerals therefrom. Froth treatment tailings may be further processed as “whole tailings”, or froth treatment tailings may be separated and fractions of the separated froth treatment tailings may be further processed. Examples in the art of methods for further processing froth treatment tailings to recover bitumen and/or heavy minerals therefrom may be found in Canadian Patent No. 2,426,113 (Reeves et al), Canadian Patent Application No. 2,548,006 (Erasmus et al), and Canadian Patent Application No. 2,662,346 (Moran et al).
There remains a need in the art for methods for separating feed materials comprising solid mineral material, water and bitumen, wherein the feed materials are derived from a process for recovering bitumen from oil sands, and wherein representative feed materials may include (but are not limited to) a bitumen froth, whole froth treatment tailings, and/or fractions of whole froth treatment tailings.